The present invention relates generally to the field of seismic exploration and, in more particular, to methods of quantifying and visualizing subsurface structural and stratigraphic features in two and three dimensions. This invention also relates to the field of seismic attribute generation and the use of seismic attributes to detect the presence of hydrocarbons in the subsurface. Additionally, it relates to the correlation of seismic attributes with subsurface features that are conducive to the migration, accumulation, and presence of hydrocarbons. The invention disclosed herein will be most fully appreciated by those in the seismic interpretation and seismic processing arts.
A seismic survey represents an attempt to map the subsurface of the earth by sending sound energy down into the ground and recording the xe2x80x9cechoesxe2x80x9d that return from the rock layers below. The source of the down-going sound energy might come, for example, from explosions or seismic vibrators on land, or air guns in marine environments. During a seismic survey, the energy source is moved to various positions across the surface of the earth above a geological structure of interest. Each time the source is activated, it generates a seismic signal that travels downward through the earth, is reflected, and, upon its return, is recorded at a great many locations on the surface. Multiple source/recording combinations are then combined to create a near continuous profile of the subsurface that can extend for many miles. In a two-dimensional (2D) seismic survey, the recording locations are generally laid out along a single straight line, whereas in a three dimensional (3D) survey the recording locations are distributed across the surface in a grid pattern. In simplest terms, a 2D seismic line can be thought of as giving a cross sectional picture (vertical slice) of the earth layers as they exist directly beneath the recording locations. A 3D survey produces a data xe2x80x9ccubexe2x80x9d or volume that is, at least conceptually, a 3D picture of the subsurface that lies beneath the survey area. In reality, though, both methods interrogate some volume of the earth lying beneath the area covered by the survey.
A seismic survey is composed of a very large number of individual seismic recordings or traces. In a typical 2D survey, there will usually be several tens of thousands of traces, whereas in a 3D survey the number of individual traces may run into the multiple millions of traces. The term xe2x80x9cunstackedxe2x80x9d seismic traces is used by those skilled in the art to describe seismic traces as they are collected in field recordings. This term also is applied to seismic traces during the processing sequence up to the point where traces are xe2x80x9cstackedxe2x80x9d or averaged together. General background information pertaining 3D data acquisition and processing may be found in Chapter 6, pages 384-427, of Seismic Data Processing by Ozdogan Yilmaz, Society of Exploration Geophysicists, 1987, the disclosure of which is incorporated herein by reference. Chapter 1, pages 9 to 89, of Yilmaz contains general information relating to conventional 2D processing and that disclosure is also incorporated herein by reference.
A modern seismic trace is a digital recording (analog recordings were used in the past) of the energy reflecting back from inhomogeneities or discontinuities in the subsurface, a partial reflection occurring each time there is a change in the elastic properties of the subsurface materials. The digital samples are usually acquired at 0.002 second (2 millisecond or xe2x80x9cmsxe2x80x9d) intervals, although 4 millisecond and 1 millisecond sampling intervals are also common. Thus, each digital sample in a seismic trace is associated with a travel time (in the case of reflected energy, a two-way travel time from the surface to the reflector and back to the surface again). Further, the surface location of each trace in a seismic survey is carefully recorded and remains associated with that trace during subsequent processing. This allows the seismic information contained within the traces to be later correlated with specific surface and subsurface locations, thereby providing a means for posting and contouring seismic dataxe2x80x94and attributes extracted therefromxe2x80x94on a map (i.e., xe2x80x9cmappingxe2x80x9d).
The data in a 3D survey are amenable to viewing in a number of different ways. First, horizontal xe2x80x9cconstant time slicesxe2x80x9d may be extracted from a stacked or unstacked seismic volume by collecting all of the digital samples that occur at the same travel time. This operation results in a 2D plane of seismic data. Similarly, a vertical plane of seismic data may be taken at an arbitrary azimuth through the volume by collecting and displaying the seismic traces that lie along a particular line. This operation, in effect, extracts an individual 2D seismic line from within the 3D data volume.
Seismic data that have been properly acquired and processed can provide a wealth of information to the explorationist, one of the individuals within an oil company whose job it is to locate potential drilling sites. For example, a seismic profile gives the explorationist a broad view of the subsurface structure of the rock layers and often reveals important features associated with the entrapment and storage of hydrocarbons such as faults, folds, anticlines, unconformities, and sub-surface salt domes and reefs, among many others. During the computer processing of seismic data, estimates of subsurface rock velocities are routinely generated and near surface inhomogeneities are detected and displayed. In some cases, seismic data can be used to directly estimate rock porosity, water saturation, and hydrocarbon content. Less obviously, seismic waveform attributes such as phase, peak amplitude, peak-to-trough ratio, and a host of others, can often be empirically correlated with known hydrocarbon occurrences and that correlation subsequently applied to seismic data collected over other exploration targets.
That being said, one of the most challenging tasks facing the seismic interpreterxe2x80x94one of the individuals within an oil company that is responsible for reviewing and analyzing the collected seismic dataxe2x80x94is locating these stratigraphic and structural features of interest within individual seismic lines or, more problematically, within potentially enormous seismic volumes. By way of example only, it can be important for exploration purposes to locate regions in the subsurface in which the frequency content of seismic events reflected therefrom and transmitted therethrough are different from the surrounding rocks, as these oft-times subtle frequency changes may be indicative of the presence of fluids (including gas) in the subsurface rocks. Additionally, rock stratigraphic information may be revealed through the analysis of spatial variations in a seismic reflector""s character because these variations may often be empirically correlated with changes in reservoir lithology or fluid content. Since the precise physical mechanism which gives rise to these variations may not be well understood, it is common practice for interpreters to calculate a variety of attributes from the recorded seismic data and then plot or map them, looking for an attribute that has some predictive value. Given the enormous amount of data collected in a 3-D volume, further automated methods of enhancing the appearance of subsurface features related to the migration, accumulation, and presence of hydrocarbons are sorely needed.
Before proceeding to a description of the present invention, however, it should be noted and remembered that the description of the invention which follows, together with the accompanying drawings, should not be construed as limiting the invention to the examples (or preferred embodiments) shown and described. This is so because those skilled in the art to which the invention pertains will be able to devise other forms of this invention within the ambit of the appended claims.
The instant inventor has discovered an improved frequency domain based method of generating attributes from 2D or 3D seismic data. The central idea of the instant invention is that if a curve characterized by one or more constant coefficients is fitted to a Fourier transform amplitude or phase spectrum that has been calculated over a relatively short time window, the coefficient estimates that are obtained thereby are seismic attributes that can be used to detect changes in subsurface properties that may be associated with the generation, migration, accumulation, or presence of hydrocarbons. Since it is well known that many subsurface structural and stratigraphic features alter the frequency characteristics of seismic waveforms passing therethrough, the instant invention provides a new way to search through large numbers of seismic traces for frequency changes that may be correlated with subsurface features of exploration interest.
As a preliminary step, the instant method typically begins with the selection of an input 2D or 3D seismic data set that has been collected over a predetermined volume of the earth that contains structural or stratigraphic features of interest to the explorationist. The selected seismic traces may either be stacked or unstacked, however stacked seismic traces are the preferred input data for use with this invention.
As a next step, a zone of interest within seismic data is specified and an initial analysis window within the zone of interest is selected. The zone of interest is preferably defined in terms of time (or depth) and lateral extent within the selected seismic data set. The time span of the analysis window will typically be somewhat smaller than that of the zone of interest and the instant inventor contemplates that a series of sliding analysis windows will be used to temporally xe2x80x9ccoverxe2x80x9d the entire zone of interest. In the case of a 3D data set, each analysis window ultimately gives rise to a 2-D xe2x80x9cplanexe2x80x9d of coefficientsxe2x80x94one coefficient being supplied by each seismic trace in the volumexe2x80x94so that, by performing the steps that follow on a large number of windows, a 3-D volume may be constructed by combining the resulting 2-D planes. When the instant method is applied to 2-D seismic data, the output data set (assuming that multiple analysis windows are employed) is again a 2-D data set.
Within each analysis window, a Fourier transform phase or amplitude spectrum is next calculated using the samples contained therein. The resulting spectrum is then fit by a function characterized by constant coefficients, thereby resulting in a collection of coefficient estimates that are associated with this spectrum and function. One of the coefficient estimates from the curve fit is then selected and displayed at the same relative location (in space and time) as the center of the analysis window. This coefficient estimate reflects (depending on which particular coefficient is chosen) some feature related to the overall shape of the spectrum and, hence, the frequency content of the seismic trace from which it was calculated. For example, frequency spectra that are front (i.e., low frequency) loaded can be differentiated from those that are rear (i.e., high frequency) loaded because those spectra have different overall shapes, which shapes will be reflected in the estimated coefficient values. Further, spectra that are unimodal in shape can be differentiated from those that are bimodal (e.g., those spectra that contain a pronounced frequency notch). Clearly, many other variations are possible.
If a number of seismic traces/analysis windows are processed by the previous method, the resulting coefficients can be assembled into seismic traces, lines, slices/planes and volumes which are suitable for viewing by the explorationist. Depending on the particular fitting function and coefficient selected for viewing, the explorationist will in a position to quantitatively assess changing frequency content and changes spectral shape, and to correlate those changes with the subsurface lithology. Since it is well known that subsurface geology can induce changes in the frequency content of seismic data, this method provides a way for the explorationist to rapidly scan large volumes of seismic data for these sorts of changes.
Further, rather than displaying just individual coefficient estimates, mathematical combinations of any number of the calculated coefficients at the same time level and trace may be formed and displayed. Still further, mathematical operations may be performed using coefficient estimates from different time levels in the same trace or between the same time levels on adjacent traces.
Still further, any statistic related to the quality of the curve fit (e.g., statistical correlation or xe2x80x9cR2xe2x80x9d) can also be calculated and used as a seismic attribute. Even further, the display of the resulting seismic attribute might be conditioned on how well each spectrum is fit by the selected equation with, for example, attributes corresponding to xe2x80x9cgoodxe2x80x9d fits being displayed while those corresponding to xe2x80x9cbadxe2x80x9d fits being set to some null value. This would help the explorationist judge whether a particular frequency change was truly representative of the underlying data or was a spurious result based on noise.
Each of the coefficients that results from the above fitting process is a seismic attribute that may be displayed and empirically or automatically correlated with subsurface structure or stratigraphy. The output from the instant method is a new seismic attribute that quantifies the shape of the spectrum and yields an attribute that numerically characterizes that shape. In the past, these frequency spectra could only be examined one-at-a-time, if the goal was to ascertain the overall shape of each spectrum. However, the instant method provides a way to look at large numbers of spectral shapes in their proper spatial relationship and to delimit the areal extent of particular shapes. This method can be used on stacked or unstacked seismic data, 2D or 3D.
While this invention is susceptible of embodiment in many different forms, there is shown in the drawings, and will hereinafter be described in detail, one or more specific embodiments of the instant invention. It should be understood, however, that the present disclosure is to be considered an exemplification of the principles of the invention and is not intended to limit the invention to any specific embodiments or algorithms so described.